Oil sands are a type of unconventional petroleum deposit. The sands contain naturally occurring mixtures of sand, clay, water, and a dense and extremely viscous form of petroleum technically referred to as “bitumen,” but which may also be called heavy oil or tar. Many countries in the world have large deposits of oil sands, including the United States, Russia, and the Middle East, but the world's largest deposits occur in Canada and Venezuela. Bitumen is a thick, sticky form of crude oil, so heavy and viscous (thick) that it will not flow unless heated or diluted with lighter hydrocarbons. At room temperature, bitumen is much like cold molasses. Often times, the viscosity can be in excess of 1,000,000 cP.
Due to their high viscosity, these heavy oils are hard to mobilize, and they generally must be made to flow in order to produce and transport them. One common way to heat bitumen is by injecting steam into the reservoir. Steam Assisted Gravity Drainage (SAGD) is the most extensively used technique for in situ recovery of bitumen resources in the McMurray Formation in the Alberta Oil Sands (Butler, 1991).
In a typical SAGD process, shown in FIG. 1A-B, two horizontal wells are vertically spaced by 4 to 10 meters (m). The production well is located near the bottom of the pay and the steam injection well is located directly above and parallel to the production well. In SAGD, a “startup” or “preheat” period is required before production can begin. The typical startup lasts 3-6 months, and during that time, steam is injected continuously into both wells until the wells are in fluid communication. At that time, the lower well is converted over to a producer, and steam is injected only into the injection well, where it rises in the reservoir and forms a steam chamber.
With continuous steam injection, the steam chamber will continue to grow upward and laterally into the surrounding formation. At the interface between the steam chamber and cold oil, steam condenses and heat is transferred to the surrounding oil. This heated oil becomes mobile and drains, together with the condensed water from the steam, into the production well due to gravity within steam chamber.
This use of gravity gives SAGD an advantage over conventional steam injection methods. SAGD employs gravity as the driving force and the heated oil remains warm and movable when flowing toward the production well. In contrast, conventional steam injection displaces oil to a cold area, where its viscosity increases and the oil mobility is again reduced.
Conventional SAGD tends to develop a cylindrical steam chamber with a somewhat tear drop or inverted triangular cross section. With several SAGD well pairs operating side by side, the steam chambers tend to coalesce near the top of the pay, leaving the lower “wedge” shaped regions midway between the steam chambers to be drained more slowly, if at all. Operators may install additional producing wells in these midway regions to accelerate recovery, as shown in FIG. 2, and such wells are called “infill” wells, filling in the area where oil would normally be stranded between SAGD well-pairs.
Although quite successful, SAGD does require enormous amounts of water in order to generate a barrel of oil. Some estimates provide that 1 barrel of oil from the Athabasca oil sands requires on average 2 to 3 barrels of water, although with recycling the total amount can be reduced to 0.5 barrel. In addition to using a precious resource, additional costs are added to convert those barrels of water to high quality steam for downhole injection. Therefore, any technology that can reduce water or steam consumption has the potential to have significant positive environmental and cost impacts.
One method of reducing steam use is to co-inject a solvent with the steam into the reservoir. Currently, expanding solvent-SAGD or “ES-SAGD” is being tested and is demonstrating promising results. The underlying theory is for steam to condense, contributing latent heat to the formation, followed by the condensation and diffusion of the liquid solvent into the bitumen. This decreases the viscosity of the heavy oil, consequently increasing the rate of production and the overall recovery more than a process driven solely by steam. The steam oil ratio (SOR) will thereby be reduced.
In practice, to make the ES-SAGD economical, the solvent is recovered and reused. However, the injected solvent often gets trapped in reservoir formations of poor quality, such as inclined heterolithic stratification (“IHS”) beds/surfaces that overlay sandstone layers at the top of pay. For example, bitumen reservoirs dominated by inclined heterolithic stratification (IHS) are found in large point bars of the Aptian (Lower Cretaceous) McMurray Formation in the northwestern part of the Corner oil sand lease (Alberta, Canada). In such reservoirs, the solvent moves further away from the drainage interface via diffusion/dispersion and fingering, resulting in solvent not being recovered in a timely fashion and reducing the overall cost effectiveness of ES-SAGD. This phenomenon of higher solvent retention has a negative impact on field development economics when solvent processes are applied.
Therefore, although beneficial, the ES-SAGD concept could be further developed to address some of these disadvantages or uncertainties. In particular, a method that reduces solvent retention, especially in reservoirs with significant inclined heterolithic stratification, would be beneficial.